Not Applicable.
Not Applicable.
1. Field of the Invention
The present invention relates generally to oil well logging and monitoring. More particularly, the present invention relates to determining the acoustic properties of a borehole fluid.
2. Description of the Related Art
To recover oil and gas from subsurface formations, wellbores or boreholes are drilled by rotating a drill bit attached at an end of a drill string. The drill string includes a drill pipe or a coiled tubing that has a drill bit at its downhole end and a bottom hole assembly (BHA) above the drill bit. The wellbore is drilled by rotating the drill bit by rotating the tubing and/or by a mud motor disposed in the BHA. A drilling or wellbore fluid commonly referred to as the xe2x80x9cmudxe2x80x9d is supplied under pressure from a surface source into the tubing during drilling of the wellbore. The drilling fluid operates the mud motor (when used) and discharges at the drill bit bottom. The drilling fluid then returns to the surface via the annular space (annulus) between the drill string and the wellbore wall or inside. Fluid returning to the surface carries the rock bits (cuttings) produced by the drill bit as it disintegrates the rock to drill the wellbore.
A wellbore is overburdened when the drilling fluid column pressure is greater than the formation pressure. In overburdened wellbores, some of the drilling fluid penetrates into the formation, thereby causing a loss in the drilling fluid and forming an invaded zone around the wellbore. It is desirable to reduce the fluid loss into the formation because it makes it more difficult to measure the properties of the virgin formation, which are required to determine the presence and retrievability of the trapped hydrocarbons. In underbalanced drilling, the fluid column pressure is less than the formation pressure, which causes the formation fluid to enter into the wellbore. This invasion may reduce the effectiveness of the drilling fluid.
A substantial proportion of the current drilling activity involves directional boreholes (deviated and horizontal boreholes) and/or deeper boreholes to recover greater amounts of hydrocarbons from the subsurface formations and also to recover previously unrecoverable hydrocarbons. Drilling of such boreholes require the drilling fluid to have complex physical and chemical characteristics. The drilling fluid is made up of a base such as water or synthetic material and may contain a number of additives depending upon the specific application. A major component in the success the drilling operation is the performance of the drilling fluid, especially for drilling deeper wellbores, horizontal wellbores and wellbores in hostile environments (high temperature and pressure). These environments require the drilling fluid to excel in many performance categories. The drilling operator and the mud engineer determine the type of the drilling fluid most suitable for the particular drilling operations and then utilize various additives to obtain the desired performance characteristics such as viscosity, density, gelation or thixotropic properties, mechanical stability, chemical stability, lubricating characteristics, ability to carry cuttings to the surface during drilling, ability to hold in suspension such cuttings when fluid circulation is stopped, environmental harmony, non-corrosive effect on the drilling components, provision of adequate hydrostatic pressure and cooling and lubricating impact on the drill bit and BHA components.
A stable borehole is generally a result of a chemical and/or mechanical balance of the drilling fluid. With respect to the mechanical stability, the hydrostatic pressure exerted by the drilling fluid in overburdened wells is normally designed to exceed the formation pressures. This is generally controlled by controlling the fluid density at the surface. To determine the fluid density during drilling, the operators take into account prior knowledge, the behavior of rock under stress, and their related deformation characteristics, formation dip, fluid velocity, type of the formation being drilled, etc. However, the actual density of the fluid is not continuously measured downhole, which may be different from the density assumed by the operator. Further, the fluid density downhole is dynamic, i.e., it continuously changes depending upon the actual drilling and borehole conditions, including the downhole temperature and pressure. Thus, it is desirable to determine density of the wellbore fluid downhole during the drilling operations and then to alter the drilling fluid composition at the surface to obtain the desired density and/or to take other corrective actions based on such measurements.
As noted above, an important function of the drilling fluid is to transport cuttings from the wellbore as the drilling progresses. Once the drill bit has created a drill cutting, it should be removed from under the bit. If the cutting remains under the bit it is redrilled into smaller pieces, adversely affecting the rate of penetration, bit life and mud properties. The annular velocity needs to be greater than the slip velocity for cuttings to move uphole. The size, shape and weight of the cuttings determine the viscosity necessary to control the rate of settling through the drilling fluid. Low shear rate viscosity controls the carrying capacity of the drilling fluid. The density of the suspending fluid has an associated buoyancy effect on cuttings. An increase in density usually has an associated favorable affect on the carrying capacity of the drilling fluid. In horizontal wellbores, heavier cuttings can settle on the bottom side of the wellbore if the fluid properties and fluid speed are not adequate. Cuttings can also accumulate in washed-out zones. Determining the density of the fluid downhole provides an indication of whether cuttings are settling or accumulating at any place in the wellbore.
In the oil and gas industry, various devices and sensors have been used to determine a variety of downhole parameters during drilling of wellbores. Such tools are generally referred to as the measurement-while-drilling (MWD) tools. The general emphasis of the industry has been to use MWD tools to determine parameters relating to the formations, physical condition of the tool and the borehole. Very few measurements are made relating to the drilling fluid. The majority of the measurements relating to the drilling fluid are made at the surface by analyzing samples collected from the fluid returning to the surface. Corrective actions are taken based on such measurements, which in many cases take a long time and do not represent the actual fluid properties downhole.
The problems outlined above are in large part addressed by a self-calibrated ultrasonic method of in-situ measurement of borehole fluid acoustic properties. In a preferred embodiment of the present invention, a method for determining a borehole fluid property includes (i) generating an acoustic signal within a borehole fluid, (ii) receiving reflections of the acoustic signal from the fluid, and (iii) analyzing a reverberation portion of the acoustic signal to determine the property. The analyzing of the reverberation portion may include obtaining a theoretical reverberation signal and relating the measured reverberation signal with the theoretical reverberation signal to determine the borehole fluid property.
In another preferred embodiment of the present invention, a processor adapted to provide real-time estimates of a borehole fluid property includes an input terminal and a processing portion. The input terminal receives a data signal corresponding to a reflected acoustic wave. The processing portion separates the data signal into a first reflection portion and a resonance portion and convolves the first reflection portion response to yield a theoretical reverberation response.
In yet another preferred embodiment of the present invention, a tool for measuring borehole fluid properties includes a body, an acoustic transducer, and a metal disk. The body houses the transducer and metal disk. A borehole fluid enters the tool through an opening in the body, flows in between the transducer and metal disk where it is measured, and exits the tool.
Thus, the present invention comprises a combination of features and advantages which enable it to overcome various problems of prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings.